Human activities have an impact upon the levels of greenhouse gases in the atmosphere, which in turn is believed to affect the world's climate. Changes in atmospheric concentrations of greenhouse gases have the effect of altering the energy balance of the climate system and increases in anthropogenic greenhouse gas concentrations are likely to have caused most of the increases in global average temperatures since the mid-20th century. Earth's most abundant greenhouse gases include carbon dioxide, methane, nitrous oxide, ozone and chlorofluorocarbons. The most abundantly-produced of these by human industrial activity is CO2.
Various strategies have been conceived for permanent storage of CO2. These strategies include sequestration of gases in various deep geological formations (including saline aquifers and exhausted gas fields), liquid storage in the ocean, and solid storage by reaction of CO2 with metal oxides to produce stable carbonates.
The most promising of these strategies is sequestration in geological formations. In these strategies, CO2, generally in supercritical (SC) form, is injected directly into underground geological formations. Oil fields, gas fields, saline aquifers, un-minable coal seams, and saline-filled basalt formations have been suggested as storage sites. Various physical (e.g., highly impermeable cap-rock), solubility and geochemical trapping mechanisms are generally expected to prevent the CO2 from escaping to the surface. Geo-sequestration can also be performed for other suitable gases.
Saline aquifers contain highly mineralized brines, and have so far been considered of little benefit to humans. Saline aquifers have been used for storage of chemical waste in a few cases, and attempts have been made to use such aquifers to sequester CO2. The main advantage of saline aquifers is their large potential storage volume and their common occurrence. One disadvantage of any practical use of saline aquifers for this purpose is that relatively little is known about them. Leakage of CO2 back into the atmosphere has been considered a potential problem in saline aquifer storage.
The densest concentration of CO2 that can be placed in a porous formation such as a saline aquifer is when CO2 is in a supercritical state—referred to herein as SC—CO2. Most sequestration schemes are based on injection of SC—CO2 in this supercritical state when the material behaves as a relatively dense compressible liquid with an extremely low viscosity, far lower than any formation liquid. The object is to displace most or all of the water in the saline aquifer, replacing 100% or some fraction of the porosity with SC—CO2.
Injection of gaseous CO2 (i.e. not in supercritical form) into a subsurface formation in solution with water at the maximum solubility limit is another approach to sequestration of this gas that has been proposed with mixed success in the past. Prior to the present invention, a problem of sequestering of CO2 by dissolution in an aqueous solution within geological formations has been that the porous volume of the formation is occupied far less efficiently than the occupation which occurs upon injection of SC—CO2. Once the active injection phase is completed, there is no more active mixing within the porous medium. Thereafter, the dissolution of the CO2 within the formation water is controlled by the concentration differences, the contact area, and the diffusion path length. Mass transfer rates associated with such concentration gradient-driven diffusion processes in porous media are slow and it is expected that thousands of years may be required to approach full dissolution of the CO2 in the aqueous phase within the geological formation.
The “reduced-mixing, long-term concentration gradient diffusion” problem persists even with injection of SC—CO2. At the high injection rates proposed for SC—CO2 sequestration, the SC—CO2 will first displace water and occupy the pore space directly, with only a small amount of convective and dispersive-occurring mixing at the displacement fronts. As SC—CO2 is injected over time, a growing area of contact is generated between the two fluids and a dissolution zone is generated. The SC—CO2 then becomes dissolved into the saline water along this contact area, largely as the result of diffusion and dispersion associated with forced advection caused by pressure driven flow (from injection of the SC—CO2 under pressure).
Because of the density difference between saline water and SC—CO2, there are also gravitational forces that will tend to segregate the liquids in the saline aquifer: the SC—CO2 will rise above the denser water, forming a “pancake” under zones that are finer-grained with poorer permeability (shale streaks, siltstones, etc.). This not only suppresses part of the mixing component that would arise in a more uniform displacement, it also leads to a significant inefficiency in the access to the pore volumes in the formation: portions of the formation remote from the injection point are largely inaccessible to any storage mechanism (displacement by or dissolving of CO2 into solution).
Once the injection ceases, only a small fraction of the SC—CO2 has gone into solution because of the mixing and diffusive effects at the displacement fronts, and because the advective driving force (injection pressure) ceases. The CO2 can no longer be advectively mixed with the water, and this leaves only diffusion effects that are driven solely by concentration gradients of CO2 in the water.
In a saline aquifer formation, after injection, the SC—CO2 remains high in the zone above the injection site due to its lesser density. This density-graded system provides a stabilizing force that further reduces the rate of any diffusion process. Initially, the diffusion front is relatively narrow and distinct with large surface area between the CO2 and water and the solution process happens relatively efficiently. But over time this front grows and widens vertically. As a result, the front becomes less distinct. This produces a thicker diffusion or transition zone with less surface area between the CO2 and water that has a low CO2 concentration (i.e. the transition-dissolution-contact area between the SC—CO2 and the formation water becomes enriched with CO2. The vertical distance between water from remote regions of the formation and SC—CO2 grows as CO2-unsaturated water is further away from the SC—CO2. Hence the diffusion/solution process slows considerably. As a result it can take many thousands of years for CO2 to enter into solution, since in situ movement of water at remote regions of the formation (to facilitate the CO2 in solution with water process) is very slow. At this stage, there is no convective mixing between the SC—CO2 and the formation water due to the density graded system.
These prior strategies require that the geologic formation include a high integrity cap rock to prevent the escape and limit the movement of the injected CO2 or SC—CO2. Residual trapping of a non-wetting liquid phase in a brine reservoir may be an important mechanism for long-term CSS. Residual trapping can potentially relax stringent requirements for the integrity of cap rocks and allow utilization of open or dipping structures for carbon storage.
At this time, a method for immobilizing CO2 in geologic formations having questionable cap rock integrity and/or in an open or dipping geologic formation for hundreds to millions of years has not been developed.
A need remains, therefore, for a method to immobilize CO2 in geologic formations having questionable cap rock integrity and/or in an open or dipping geologic formation for hundreds to millions of years.